The production of fluids from subterranean formations may utilize subterranean wells to transport the fluids from the subterranean formation to a surface region and/or to provide stimulant fluids to the subterranean formation. These subterranean wells may be created using a downhole assembly, such as a drilling assembly, to drill a wellbore, which may form a portion of the subterranean well. Drilling assemblies may include a plurality of portions, regions, components, parts, segments, and/or sections, each of which may serve a specific purpose during creation of the wellbore. These sections may include a cross-sectional area, and this cross-sectional area may vary from section to section and/or within individual sections.
As an illustrative, non-exclusive example, the downhole assembly may include a drill pipe and a bottom-hole assembly. The drill pipe typically will form a mechanical and fluid connection between the surface region and the bottom-hole assembly. In addition, a cross-sectional area and/or a diameter of the drill pipe may be less than a cross-sectional area and/or diameter of the bottom-hole assembly.
During a drilling process, the bottom-hole assembly, which may include a drill bit, may be in at least temporary mechanical contact with a terminal end of the wellbore and may remove material, which may be referred to herein as cuttings, from the terminal end of the wellbore to increase a length of the wellbore. The downhole assembly also may include a drilling fluid conduit that is configured to provide a drilling fluid stream to the wellbore, such as to the terminal end thereof, via the bottom-hole assembly. The drilling fluid stream may lubricate at least a portion of the bottom-hole assembly, cool at least a portion of the bottom-hole assembly, and/or provide a motive force for removal of at least a portion of the cuttings from the wellbore by flowing the cuttings to the surface region via an annular space that is present between the downhole assembly and the wellbore.
However, a portion of the cuttings may remain within the wellbore. These cuttings may settle and/or otherwise accumulate and may produce a cuttings bed on and/or near a bottom surface of the wellbore. The size, or extent, of this cuttings bed, or, alternatively, a fraction of the cuttings that remain within the wellbore to form the cuttings bed, may vary with a variety of factors. Illustrative, non-exclusive examples of such factors may include a flow rate of the drilling fluid stream, a diameter of the wellbore, a diameter of the downhole assembly, a size of the cuttings, a density of the cuttings, a viscosity of the drilling fluid, and/or an orientation of the wellbore.
As an illustrative, non-exclusive example, a horizontal, substantially horizontal, and/or highly inclined wellbore may include a larger cuttings bed than a vertical, or substantially vertical, wellbore. This may be caused, at least in part, by a tendency for the cuttings to settle under the influence of gravity to the bottom, or other horizontal, substantially horizontal, and/or highly inclined (i.e., away from a vertical orientation) surface of the wellbore and/or a tendency for the drilling fluid to flow, or channel, near an upper surface of the wellbore. As another illustrative, non-exclusive example, a wellbore that includes a breakout region, wherein a cross-sectional area of the wellbore is greater than a nominal cross-sectional area of the wellbore, may include a larger cuttings bed in the vicinity of the breakout region. This may be caused by a decrease in the flow rate of the drilling fluid stream within the breakout region due to the larger cross-sectional area of the wellbore in the breakout region.
During and/or after completion of the drilling process, at least a portion of the downhole assembly may be withdrawn from, drawn out of, pulled from, taken out of, removed from and/or otherwise moved within the wellbore. This motion may include drawing, pulling, and/or pushing the downhole assembly within the wellbore and along a longitudinal axis of the downhole assembly, such as toward the surface region and/or toward the terminal end of the wellbore. In conjunction with pulling and/or pushing, the downhole assembly may be rotated and/or drilling fluid may be circulated through the drill pipe, the bottom hole assembly, and/or the drill bit and up the annular space. Motion of the downhole assembly within the wellbore may push, move, collect, and/or otherwise accumulate at least a portion of the cuttings bed present within the wellbore, leading to the formation of a cuttings dune. As an illustrative, non-exclusive example, a transition region between a first section of the downhole assembly, which includes a first cross-sectional area, and a second section of the downhole assembly, which includes a second cross-sectional area that is larger than the first cross-sectional area, may facilitate, or otherwise contribute to, formation of a cuttings dune.
Under certain circumstances, the cuttings dune may generate a packoff event, which may preclude further motion of the downhole assembly within the wellbore. The occurrence of the packoff event may result in abandonment of at least a portion of the wellbore, require drilling a new section of the wellbore adjacent to the location of the packoff event, and/or result in abandonment of the bottom-hole assembly in the wellbore, any of which may substantially increase the costs associated with, and/or time needed to complete, the drilling operation.